Fracturing or other treatment processes are conventionally used to increase hydrocarbon conductivity through subterranean formations. Fracturing or other stimulation procedures are usually performed in production wells. However, injection wells used in secondary or tertiary recovery operations may also be fractured or otherwise treated to facilitate the injection of fluids into subterranean formations.
Hydraulic fracturing includes injecting a fracturing fluid into the well at a pressure sufficient to cause one or more cracks or “fractures” in the formation. Usually the fracturing fluid is a gel, an emulsion, or a foam for carrying a proppant, such as sand or other particulate material, into the fracture. The fracturing fluid is made to have a sufficiently high viscosity to retain the proppant in suspension or at least to reduce the tendency of the proppant to settle out of the fracturing fluid as the fracturing fluid flows through the well and into the newly-created fracture.
Once the fracturing fluid carrying the proppant has been pumped into the formation, the high-viscosity of the fluid is then “broken” to deposit the proppant in the fracture and allow the fluid to flow back from the formation. Breaking the gel entails the conversion of the gelled or emulsified high-viscosity fluid into a low-viscosity fluid.
After the treatment, the newly-created fractures, which are held open by the proppant, provide increased fluid conductivity through the formation. This can dramatically increase the hydrocarbon production from the formation, through the fracture, and into the well bore.
In an aqueous fracturing fluid, a gelation agent and/or an emulsifier are used to gel or emulsify the fracturing fluid and provide the required high viscosity to carry the proppant. A “breaker,” or a viscosity-reducing agent, is added to the fracturing fluid prior to pumping the fracturing fluid into the subterranean formation.
The treatment fluid's effectiveness depends largely on the ability to control the timing of when the high viscosity of the fluid is broken. If the high-viscosity fluid breaks too soon, the proppant will settle out of the fracturing fluid in the well bore, before it is carried into the formation. If the high-viscosity fluid takes too long to break, valuable hydrocarbon production may be lost, or worse, the formation may be permanently damaged by the long “shut in” time.
Controlling the timing of the breaking of the high-viscosity treatment fluids has been difficult. Breaking of the fluid can be unreliable often resulting s in premature breaking, excessively delayed breaking, and incomplete breaking of the high-viscosity treatment fluid. The ability to control the fluid degradation rate is essential to a successful stimulation treatment. While most fracturing fluids will break, even in the presence of a gel stabilizer, if shut-in for a sufficient time, it is most desirable to return the well back to production as quickly as possible. The break time for gelled fluids is usually desired to be within 1 to 24 hours after introduction into the subterranean formation.
Temperature is a major factor in the chemistry of breaking fluids. The break rate tends to increase dramatically with increasing temperature. Further, the stability of the gelled fluids tends to decrease and the stability of the breaker also can become a problem. Thus, the ability to control the timing of breaking the fluid becomes increasingly difficult in formations having higher static temperatures.
For example, at static temperatures up to about 200° F., conventional oxidizing breakers such as alkali metal or ammonium persulfates, sodium perborate, and t-butyl hydroperoxide have been used as breakers for treatment fluids. Laboratory evaluations are routinely made before the treatment to find the breaker concentration necessary to cause a reasonable rate of viscosity decline. However, above 180° F., the conventional breakers have been difficult to control and often result in premature breaking of the treatment fluids.
At static temperatures near and above 200° F., alkali metal chlorite, lithium hypochlorite, or sodium hypochlorite activated with an amine and/or copper ion have been used as breakers for treatment fluids. These have been partially effective at such higher temperatures. However, alkali metal chlorite, lithium hypochlorite, or sodium hypochlorite breakers often exhibit inconsistent degradation rates.
Attempts to slow or control the break rate of guar-based fracturing fluids have been made by decreasing the breaker concentration that is added to the treatment fluid. In field practice, this technique works to a degree, but the minute concentrations required for a controlled break of some applications are not practical. Also, there are several drawbacks associated with this approach to control break rate. For example, at very low chlorite concentration, incomplete fluid breaking is often encountered. Further, low chlorite concentrations are often difficult to meter and susceptible to inhibition or degradation.
Thus, the break rate of chlorite and hypochlorite breakers has been difficult to control in the past, which has limited the application of these breakers in stimulation operations such as fracturing. Therefore, there is a need to provide a means by which the break rate of chlorite and hypochlorite breakers could better controlled in well treatment fluids.